1. Field of the Invention
The invention relates generally to the field of oil and gas production. More particularly, the invention relates to a method of deliquifying a well to enhance production.
2. Background of the Technology
Geological structures that yield gas typically produce water and other liquids that accumulate at the bottom of the wellbore. The liquids can come from condensation of hydrocarbon gas (condensate) or from interstitial water in the reservoir. In either case, the higher density liquid-phase, being essentially discontinuous, must be transported to the surface by the gas.
In some hydrocarbon producing wells that produce both gas and liquid, the formation gas pressure and volumetric flow rate are sufficient to lift the produced liquids to the surface. In such wells, accumulation of liquids in the wellbore generally does not hinder gas production. However, in the event the gas phase does not provide sufficient transport energy to lift the liquids out of the well (i.e. the formation gas pressure and volumetric flow rate are not sufficient to lift the produced liquids to the surface), the liquid will accumulate in the wellbore.
In many cases, the hydrocarbon well may initially produce gas with sufficient pressure and volumetric flow to lift produced liquids to the surface, however, over time, the produced gas pressure and volumetric flow rate decrease until they are no longer capable of lifting the produced liquids to the surface. The accumulation of liquids in the well impose an additional back-pressure on the formation and may begin to cover the gas producing portion of the formation, thereby restricting the flow of gas, thereby restricting the flow of gas and detrimentally affecting the production capacity of the well. Once the liquid will no longer flow with the produced gas to the surface, the well will eventually become “loaded” as the liquid hydrostatic head begins to overcome the lifting action of the gas flow, at which point the well is “killed” or “shuts itself in.” Thus, the accumulation of liquids such as water in a natural gas well tends to reduce the quantity of natural gas which can be produced from a given well. Consequently, it may become necessary to use artificial lift techniques to remove the accumulated liquid from the wellbore to restore the flow of gas from the formation.
There are several methods for removing liquids from a gas well. One method of removing liquid from a gas well is to blow the well down to a lower surface pressure, such as atmospheric pressure or the pressure in a storage tank. This may be done following a shut-in to allow the well downhole pressure to build up to a value sufficient to overcome the liquid hydrostatic head, whereupon the well will again flow and produce both gas and liquid to the surface. However, the well may only flow and produce gas and liquid to the surface until the accumulation of liquid once again produces a hydrostatic head sufficient to overcome the produced gas pressure and volumetric flow, at which point the well shuts itself in once again. Further, for some wells (e.g., very low pressure gas wells), the pressure build-up during shut-in may still be insufficient to overcome the liquid hydrostatic head.
Another common method for removing liquids from a gas well with insufficient bottom hole pressure, is to run a relatively small diameter siphon string into the well, close in the annulus between the siphon string and the casing, and periodically open the siphon string to atmospheric pressure. Typically, siphon strings for such application have a diameter of about 1 in. to 1.25 in. The purpose of the small diameter siphon string is to reduce the production flow area, thereby increasing gas flow velocity through the string, which may carry some of the liquids to the surface. This method is particularly applicable to low volume gas wells where a reduced production rate due to increased flowing friction is not a significant problem. This relatively simple solution results in the continuous production of both gas and liquid through the same producing string.
An alternative method employing a small diameter siphon tubing string is to produce gas up the annulus between the tubing string and the casing, and periodically unloading accumulated liquids by either swabbing the well or using a pump as a mechanical artificial lift to lift the liquids up the tubing while the gas flows up the casing. Accumulated liquids may also be removed through a siphon string by forcing liquids and gas up the siphon string by periodically subjecting the annulus between the tubing string and the casing to a relatively high pressure.
Differential pressure intermitters have also been used to unload gas wells. These devices measure the pressure differential between the siphon string and the annulus between the siphon string and casing, determine the amount of water in the siphon tubing string, and blow the well when an adequate load of water is detected. Gas is produced through the annulus, and is slowly bled from the siphon string to cause water in the wellbore to move into the siphon string. The pressure difference between the siphon string and the annulus determines the amount of water in the siphon string. However, the efficiency of the differential pressure intermitter is dependent upon the bleed rate. If the bleed rate is too slow, liquids will build up in the casing. If the bleed rate is too fast, unnecessary amounts of gas are bled from the siphon string and wasted to the atmosphere.
Yet another method for removing liquids from a well involves the use of a plunger, a free moving rod (bluff object) or sealed tube with tight fit or with loose-fitting (pads) seals to prevent fluid bypassing between the plunger and the production tubing wall. The basic operation of a plunger is to open and close the well shutoff/sales valve at the optimum times, to bring up the plunger and the fluids and/or solids that build downhole. Specifically, the plunger is left at the bottom of the well until sufficient pressure has built up to allow the plunger to rise to the top of the well head, pushing the accumulated fluid ahead of the plunger. When the shutoff valve is closed, the pressure at the bottom of the well usually builds up slowly over time as fluids and gas pass from the formation into the well. When the shutoff valve is opened, the pressure at the well head is lower than the bottomhole pressure, so that the pressure differential causes the plunger to travel to the surface. In some instances it is desirable to leave the shutoff valve open for a period of time after the plunger has arrived at the surface. This time period is frequently referred to as “afterflow.”
Downhole pumps can also be employed. In these installations, liquid in the well is pumped to the surface through the tubing and gas is produced up the annulus between the tubing and casing. Downhole pumps can be used to continue production in wells where the abandonment pressure is considered to be between 30 and 50 psi at the surface. Downhole pumping means are conventionally employed with wells which have been logged off and which can no longer be unloaded with siphon strings or intermitters. A typical downhole pumping unit comprises an electric motor, a pump, rods and other ancillary equipment.
Although there are several conventional methods for removing liquids from a well, few, if any, of the current methods provide an efficient means for removal of liquid from wells with multiple production formations or zones. Presently, production of commingled wells typically calls for merely using perforated tubing at the site of the upper formations or opening a sliding sleeve to give access to the upper formations but hindering the lower zone production because the tubing integrity below the perforations or sliding sleeve is lost, liquids from upper zones fall onto the lower zone further liquid loading the well, and the critical velocity below the perforation or sliding sleeve changes to that of the casing size which is much higher and unattainable by the lower zone. Such methods may cause interference and cross flow of the upper formation production with the lower formation production and, thus, affect overall productivity of the well. In addition, some of the above described methods may be cost prohibitive in times where the market value of gas is relatively low.
Consequently, there is a need for a simple and cost efficient systems and methods for removing liquid from a well using the well's own natural formation pressure and gas flow, including multi-formation wells.